This disclosure relates in general to methods and systems for measuring multiphase flows in a pipeline using a combination of venturi, microwave and radiation techniques, where the pipeline is configured to transport hydrocarbons. More specifically, but not by way of limitation, certain embodiments of the present invention provide methods and systems in which low activity radiation sources may be used in combination with one or more microwave transmitter-receiver pairs and a pressure differential sensor to measure the flow—fractions and rates of phases—in multiphase flows in a pipeline, such as may be encountered in producing hydrocarbon wells. Additionally, other embodiments of the present invention provide for the arrangement of one or more microwave transmitter-receiver pairs, one or more radiation source-detector pairs and/or one or more pressure sensor ports in the same cross-section of the throat of a venturi to measure multiphase flow in a hydrocarbon transporting pipeline.
It is desirable during the production of oil and gas to carry out flow measurements to determine the flow in a hydrocarbon transporting pipeline of individual phases of multiphase flow where the multiphase flow may consist of a two-phase or a three-phase combination of oil/water/gas. Measurements may be made in the form of mass flow rate or volume flow rate of a so-called multiphase measurement. Preferably, flow measurements may be performed using temporarily or permanently installed compact flow measurement systems that—unlike many conventional separator-based measurement systems, which separate multiphase flow into its components and then measure the flow of the component phases—are capable of measuring the flow of the phases of the multiphase flow without separation.
Measurement of the flow of the different phases—i.e. oil, gas and water—in an oil/hydrocarbon transporting pipeline is often highly desirable so as to control and regulate hydrocarbon production. For example, it may be important to measure oil being produced by not only an oilfield, but also individual oil wells associated with the oilfield. Measurements may be necessary/desirable in order to determine the water and/or the gas content of the flow being produced from individual oil wells—for production analysis, etc—and/or to allocate production amounts to individual rights owners. It is, however, in general, very difficult to obtain measurements of the flow of the different phases when the different phases—oil, water and gas—flow simultaneously through the pipeline. The problems associated with taking measurements arise, from among other things, the distribution of the three phases in the pipe—the phases may form different arrangements temporally and spatially—both axially and radially in the pipe. These different arrangements of the multiple phases may create, among other things, nonlinear responses—with the measuring system.
Flow of the multiphase fluid in the pipe may consist, among other flow designations, of a continuous phase—normally, liquid flow—or a discontinuous phase—normally, gas flow. In the continuous phase, the flow may be a continuous oil flow and the flowing oil may contain water droplets. Such flow, being primarily made up of a hydrocarbon substance, may, in general, be marked by low conductance characteristics. In the alternative, the flow may be a continuous water flow with oil droplets distributed in the continuously flowing water. In such situations, the water, which may also have varying degrees of salinity, may provide that the flowing mixture has electrically conductive characteristics that change with time due to water injection or breakthrough, especially in contrast to the oil continuous situation.
With regard to the gas in the multiphase fluid, the gas may be distributed in large volumes or pockets in the multiphase fluid as gas chums or slugs, or may be distributed as small bubbles in the liquid phase, often referred to as bubble flow. Furthermore, under high pressure, such as down-hole, gas in the multiphase fluid may be dissolved in the oil phase. When there are large volumes of gas in the pipeline the gas may govern the multiphase fluid flow and cause the oil and water phase to be pushed back to the pipe wall. In this case, often referred to as annular flow, the oil/water fluid mixture may move at a low velocity along the pipe wall. Additionally annular-mist flow may occur when gas flow dominates the multiphase flow in the pipe (and in mist flow, neither the water phase nor the oil phase is continuous). In such annular-mist flow, gas-carrying droplets of oil or water may move up the center of the pipe at high velocity while the remaining oil or water flows up along the pipe walls at low velocity.
In general, the liquid—which may be formed from multiple liquid phases mixed together—moves with a common velocity through the pipeline. However, in low flow velocity situations the oil and water may become partially or even completely separated. In such situations, the water and oil may travel at different velocities through the pipeline. For a non-horizontal pipe, the lighter oil may move up the pipe faster than the heavier water and cause small water drops to form that may in turn aggregate to form larger drops or slugs that may reach pipe diameter. This type of flow is often referred to as slug flow. The difference in velocity of the oil and water moving through the pipe is often referred to as “slip”. Because gas has a substantially lower density than oil/water or a mixture of the two, a larger slip will occur between the gas and the liquid phases.
To measure accurately the flow of the different phases of oilfield oil-water-gas multiphase flows, it is desirable to have a multiphase flow meter (“MPFM”) capable of robust flow rate measurement for all the different flow regimes—including both water-continuous flows (high water cut) and oil-continuous flows—and over a wide range of water salinity and oil viscosity. For topside applications, however, it may be difficult to obtain high-accuracy flow rate measurements because of flow instabilities, including those discussed in more detail above, such as slug, chum, annular flow, etc. Furthermore, due to these instabilities, it is often very difficult to measure water-cut using an in-line MPFM, especially for high gas-cuts. As such there exists in the art a long felt need in the art for a versatile MPFM that is capable of accurately measuring multiphase flow over a wide range of conditions. While several different MPFMs have been designed to measure multiphase flow and/or phase content of the multiphase flow, as discussed below, these designs have many design drawbacks, such as requiring the use of high-activity/non-exempt radiation sources and the requirement of interpolation of measurements because of the configuration of the different measuring apparatus in the MPFM.
U.S. Pat. No. 4,289,020 (“the '020 patent) describes a system for the limited purpose of measuring water-cut in a multiphase fluid when gas is present. As such, the '020 patent does not disclose or teach measuring actual multiphase flow in a pipe and, consequently, it does not disclose how to address the issues associated with such measurements. The '020 patent discloses using a combined transmission-microwave and gamma-ray density measuring system to measure the water-cut in the multiphase fluid with gas present. In the system, the microwave and gamma ray beams are configured obliquely with respect to the flow axis of the multiphase fluid through the pipe that is being measured. Water-cut is calculated directly from the amplitude attenuation of the microwaves passing through the multiphase fluid and the transmission of gamma rays through the multiphase fluid.
The method disclosed in the '020 patent has many limitations including but not limited to: the method is not robust—there is no solid physical basis for determining oil/water fraction purely from microwave attenuation; determining water cut based on amplitude attenuation may be inaccurate due to nonlinear attenuation effect; and the method does not provide for the use of low activity radiation sources. Embodiments of the current invention differ substantially from the '020 patent. Embodiments of the current invention provide robust measurement of phase flow that avoids nonlinearity inaccuracies by basing fluid phase measurements on permittivity and conductivity of the multiphase fluid. Embodiments of the current invention utilize pressure differential measurements provide for the use of low activity radiation sources. Embodiments of the present invention also provide for the microwave transmitter-receiver pair to be aligned in the same cross-section (as that the low-activity radiation source-detector pair is aligned), rather than oblique to the multiphase flow, to reduce the distance traversed by the microwave beam and the resultant phase wrapping effect, which may provide for using the MPFMs in larger diameter pipes and in high salinity conditions.
U.S. Pat. No. 5,101,163 (“the '163 patent) discloses measuring water fraction in an oil/water mixture by using at least one transmitting antenna and two receiving antennas. As disclosed, antennas are designed to emit and receive operating frequencies around 2.45 GHz through the multiphase fluid. The phase difference and/or the power ratio of the two received signals are determined and used with a look-up table to yield water fraction. The '163 patent discloses installing the antennas axially in such a way that one receiving antenna receives signal in the flow direction, while the other equally-spaced antenna receives its signal against the flow direction to provide for measurement of the phase difference of signals received by the two antennas, which is directly related to the flow velocity. The '163 patent does not disclose how to make corrections for instabilities in the flow due to gas nor does it disclosed how the microwave receivers' amplitude/phase difference or ratio measurements at 2.45 GHz compensate for changes in water salinity—different water salinities will cause the multiphase fluid containing the water to interact differently with the microwaves and to cause different amplitude attenuations and phase shifts.
Unlike the present invention, the '163 patent provides a method/system for measuring multiphase fluid flow that is entirely empirical and lacks a solid physics basis. Further, the '163 patent does not disclose using radiation density measurements in connection with the microwaves to make measurements that take account of multiphase fluid flow inconsistencies, including but not limited to flow inconsistencies caused by gas.
U.S. Pat. No. 5,259,239 (“the '239 patent) discloses a hydrocarbon mass flow meter that uses the principle that the permittivity of a dry hydrocarbon—oil and/or gas—is closely related to its density. As such, by determining the mixture density using a gamma-ray densitometer, the changes in the hydrocarbon permittivity can be compensated for and the flow of the phases of the multiphase fluid determined. Unlike embodiments of the current invention, the '239 patent does not disclose oil/water mixture permittivity and conductivity corrections for salinity, use of pressure change monitoring to provide for the use of a low-activity radiation source nor does it disclose configuring the microwave measuring device and the radiation densitometer in the same cross-section to eliminate interpretation factors for axially developing phase-fractions and velocities in the multiphase flow measurement.